When employing hydraulic fracturing to fracture a hydrocarbon formation in an underground reservoir, large quantities of liquids and proppant materials are injected into the reservoir. At the end of the fracturing treatment, the fracture system and reservoir are completely saturated with the fracturing fluid. To be produced, oil and gas must either flow around or through the fracture fluid saturated rock and fracture system such that the fracture fluid must be sufficiently removed from the pathway in order to not impair flow. To remove the fracturing fluids from the reservoir and fractures, a pressure differential is induced within the wellbore to draw the fracturing fluids out of the reservoir and fractures. In this manner the fracturing fluids are removed, or flowed back until sustained, stable and sufficient oil and gas production is achieved.
Once the well is placed on production, the flow of native reservoir fluids is directed from the well to a processing facility where the produced fluids are processed to a suitable specification for sales or reuse in some manner. Processing at the processing facility for natural gas may include liquids separation, dehydration, natural gas liquids capture, compression, plus contaminates removal for components such as carbon dioxide, nitrogen, sulfur, hydrogen sulfide and oxygen. The processing facility can be located in the vicinity of the wellbore or a remote location and fluidly coupled to the wellbore by a pipeline. Further, the processing facility may be applied to process native reservoir fluids from a single well, or multiple wells.
The processing facility is typically configured with the capacity and capability to process a fluid composition of primarily native reservoir fluids and at a prescribed inlet pressure, but this configuration is typically not suitable for processing a composition that includes well effluent such as fracturing fluids or the inlet pressures available during fracture fluids recovery. Most commonly, due to capacity and capability limitations of processing facilities, recovery of the injected fracturing fluids is accomplished by simply opening the well to atmosphere. Common to post-fracturing recovery, the water and proppant components of the effluent are separated from the gas component by temporary fracturing flow back equipment primarily comprised of a choke to control pressure, phase separation for solids, liquids and gases, storage and or processing for the liquids and a vent or flare to atmosphere as an outlet for the gas stream. The flow back equipment is often comprised of an open-ended conduit directing flow to a pit where the liquids and solids are separated and captured within the pit while gases are vented or burned to atmosphere. This technique maximizes the pressure differential induced within the wellbore to draw the fracturing fluids out of the reservoir plus eliminates the complexities, costs, upsets and damage that may be encountered by attempting to direct the post-fracture well stream to the production facilities.
For example consider a well which produces at least natural gas and has had nitrogen energized water based fracturing treatment completed. The processing facility has been configured to process the native well stream, which generally contains at least natural gas with 25 lb/MMscf water, 7 vol % carbon dioxide, 1 vol % nitrogen, 0 vol % sulfur, hydrogen sulfide and oxygen and with a heating content of 1025 Btu/ft3, all of which is to enter the processing facility at a minimum pressure of 75 psig. The processing facility is then configured to process this native gas to a sales specification with a target composition and condition not exceeding 7 lb/MMscf for water, 2-3 vol % for carbon dioxide, 3 vol % for nitrogen, 50 mg/m3 of sulfur, 15 mg/m3 of hydrogen sulfide and 0.4 vol % of oxygen with a heating value in the range of 950 to 1150 Btu/ft3 at an outlet pressure of 600 psi. As such, the processing facility is configured with capacity to remove at least 20 lb/MMscf water, through a dehydration process, and 5 vol % carbon dioxide, through an amine carbon dioxide capture system, from the native natural gas, and then compress the natural gas to the required outlet pressure of 600 psig. The facility will not be configured to remove nitrogen, sulfur, sulfur dioxide, or oxygen from the native gas, or to modify the heating content; as these components of the native natural gas are within sales specification. Following the fracturing treatment and during the flow back stage, the well is flowed to remove the fracturing fluids from the reservoir. This is completed using temporary fracturing flow back equipment until such time as sufficient native reservoir fluids are included within the well stream such that the well stream is within the capability of the processing facility to process to the sales specification. This is commonly referred to as the well being ‘cleaned-up’ where sufficient fracturing load fluid has been recovered and the well is placed ‘on production’. This post-fracture clean-up process or flow back stage may take two or more weeks to complete which is a relatively short time in the life of the well and does not warrant alteration of the processing facility to permit processing the post-fracture well stream. Initially during flow back of the fracturing fluids, the well stream will be comprised of virtually 100% injected fracturing materials, such as water, proppant and nitrogen gas. This gas component of this initial well stream (“gas stream”), containing nitrogen content in excess of the capability of the processing facility cannot be directed to the facility and is, by necessity vented or flared until the content is at or below 3%. As an alternative to venting or flaring the high nitrogen content gas stream, the recovered gas stream can be processed for nitrogen removal prior to entering the processing facility inlet by adding, for example, a temporary nitrogen capture membrane system. This membrane system may by necessity include dehydration to remove excess water vapor within the gas, compression to drive the gas across the membrane, venting of the separated nitrogen to atmosphere and finally additional compression of the separated natural gas to meet the minimum inlet pressure of the processing facility.
Due to the large amount of liquids typically found in a post-fracturing well stream, the pressure of the gas stream may be insufficient to meet the inlet pressure requirement of the processing facility even though the content of the gas stream may be within composition specification. The excessive liquids contained within the flow back well stream, while flowing up the wellbore from the reservoir and to surface, exhibits higher flowing pressure losses. This causes a reduction in the flowing pressure to surface, often to below the inlet pressure requirement of the processing facility. Again, this necessitates venting or flaring of the gas stream until the water content is reduced such that pressure of the stream from the well is sufficient to overcome the minimum inlet pressure of the processing facility. As an alternative, should the gas composition be within the processing facility inlet specification while the pressure is too low to meet the inlet pressure requirement, a temporary gas compressor can be applied to sufficiently increase the pressure to meet the inlet pressure requirement to avoid venting or flaring. At least dehydration for water vapor removal prior to compression is likely needed in order for the gas component of the well stream to meet the compressor's inlet requirements.
Further, should the flowing pressure losses be such that the fluids will not readily flow to surface unassisted, load fluid recovery techniques can be deployed to move fluids to surface during the flow back stage. Two examples of such techniques are swabbing and gas-lifting. Both techniques tend to be costly, complex and time consuming and are add-on processes to the flow back operation following the fracturing treatment. Swabbing involves moving mechanical devices up the wellbore to cause liquids in the wellbore to be lifted to surface. Gas-lifting involves inserting a tubing string or coiled tubing inside the well casing to a specified depth then injecting gas such as nitrogen or natural gas into the tubing or annular space between the tubing and wellbore to cause liquids to move to surface. Gas-lifting can involve extensive surface equipment such as compressors to pressurize the gas, and dehydration and cooling equipment to treat the gas prior to compression.
While there are known techniques available for processing a well stream at surface and to pressurize the well stream to a sufficient processing facility inlet pressure, these techniques can be environmentally harmful, and include techniques like venting or flaring gases to atmosphere, and depositing liquids into open pits. These temporary techniques also tend to require complicated and expensive surface equipment, which also can introduce significant pressure losses, thereby compromising the pressure differential induced within the wellbore to draw the fracturing fluids out of the reservoir. Significantly reducing or eliminating venting, flaring and the water applied during hydraulic fracture completion operations is generally difficult, expensive, complex and ineffective, yet important to the environment and ultimate sustainability of existing well completion techniques. The oil and gas industry would benefit from an effective, cost efficient, and reduced emissions method to induce flow back behaviors after hydraulic fracturing.